Hydrogen production from hydrocarbons with near zero greenhouse gas emissions

ABSTRACT

Methods and systems for producing hydrogen substantially without greenhouse gas emissions, one method including producing a product gas comprising hydrogen and carbon dioxide from a hydrocarbon fuel source; separating hydrogen from the product gas to create a hydrogen product stream and a byproduct stream; injecting the byproduct stream into a reservoir containing mafic rock; and allowing components of the byproduct stream to react in situ with components of the mafic rock to precipitate and store components of the byproduct stream in the reservoir.

PRIORITY

This application is a divisional application of U.S. patent applicationSer. No. 16/505,378, filed Jul. 8, 2019, which itself is anon-provisional patent application of and claims priority to and thebenefit of U.S. Prov. App. Ser. No. 62/830,945, filed Apr. 8, 2019, theentire disclosures of which are incorporated here by reference.

BACKGROUND Field

Embodiments of the disclosure relate to synergistic hydrogen productionand carbon capture. In particular, embodiments of the disclosure relateto hydrogen production from fossil fuels with substantially nogreenhouse gas emissions due to carbon capture via mafic rock, forexample basalts.

Description of the Related Art

Hydrogen or H₂ is an environmentally-friendly fuel which has thepotential to replace greenhouse gas emitting hydrocarbon fuels. Forexample, hydrogen can be used to power fuel cells. Nearly all H₂currently produced, greater than about 95%, is derived fromhydrocarbons, and predominantly from natural gas. Waste CO₂ released tothe atmosphere (between about 7 and 12 tons CO₂ per ton of H₂ produced)partially negates the “clean fuel” benefits of H₂. To mitigate thecarbon footprint of H₂ production, economically-impractical methods andsystems have been proposed for H₂ production combined with capturing,compressing to a liquid, and injecting co-produced CO₂ into deep(greater than about 800-850 m underground) sedimentary rock reservoirsin a process known as carbon capture and storage (“CCS”). However,conventional CCS adds significant cost to an alreadyhighly-energy-consuming H₂ production process, thus rendering thecombined technology unfeasible under current market and regulatoryconditions.

Previously-proposed combinations of H₂ production from hydrocarbons withconventional CCS of CO₂, for example in depleted hydrocarbon reservoirsor saline groundwater aquifers, adds significant costs associated withpurification, compression, transportation, and injection of CO₂. Anumber of energy-consuming steps are employed to ensure high purity ofCO₂ (greater than about 98 mol. %) needed to meet the requirements ofconventional CCS. And, since standard pressure swing adsorption (“PSA”)H₂—CO₂ separation technology alone does not produce CO₂ of sufficientquality and purity for CCS, further purification involving acid gasabsorbing reagents, such as Selexol™ (for heavy and solid hydrocarbons)and methyl diethanolamine (MDEA), is needed.

Safe and economic transportation, as well as the injection and long-termstorage of CO₂ in conventional CCS, depends upon CO₂ being compressed toa supercritical (liquid) state, which also adds significant cost.Consequently, underground CO₂ storage reservoirs must be located atleast about 850 vertical meters below the ground surface to ensure thatthere is sufficient pressure to keep CO₂ in a liquid state, thus addingto the cost of the injection and disposal wells.

Since CO₂ in conventional CCS could remain in a liquid and/or compressedgas state for hundreds or thousands of years, sophisticated long-termmonitoring programs are needed to ensure that CO₂ is truly confined to agiven CCS reservoir and does not migrate to overlying aquifers or thesurface.

SUMMARY

The present disclosure presents systems and methods for efficientproduction of hydrogen from hydrocarbon fossil fuels with little to nogreenhouse gas emissions. In some embodiments, the first step of themethod is co-production of H₂ and waste or byproduct CO₂ from gaseous,liquid, or solid hydrocarbons (for example steam reforming of naturalgas). The co-production of H₂ and CO₂ from hydrocarbons can beaccomplished in various processes. In a second step of the method, CO₂is injected into reactive mafic or ultramafic rocks, where CO₂ and/orother waste gases are permanently immobilized as precipitated carbonateminerals. The term mafic generally describes a silicate mineral origneous rock that is rich in magnesium and iron. Mafic minerals can bedark in color, and rock-forming mafic minerals include olivine,pyroxene, amphibole, and biotite. Examples of mafic rocks includebasalt, diabase, and gabbro. Examples of ultramafic rocks includedunite, peridotite, and pyroxenite. Chemically, mafic and ultramaficrocks can be enriched in iron, magnesium, and calcium.

In embodiments of systems and methods, produced hydrogen can beconverted reversibly to ammonia for safe storage and transportation in areduced volume. The versatility of the present carbon capture andstorage (“CCS”) systems and methods also allows CO₂ from other sourcessuch as refining, power production, and desalinization to be immobilizedeconomically, for example in basaltic rock.

To increase the efficiency of synergistic H₂ production with CO₂removal, H₂ production occurs preceding an alternative CCS process inwhich CO₂ dissolved in water is injected into natural geological sinkscomprised of reactive basaltic and ultramafic lithologies, where itrapidly reacts to form stable mineral phases, such as precipitatedcarbonates. Carbon storage in basalts (“CSB”) consumes significantlyless energy than other CCS systems and processes, has advantageouslyhigh tolerance to acid gas impurities (i.e., H₂S), does not require deepwells, such as those 850 m deep or deeper, and does not requirelong-term reservoir monitoring.

Storage of CO₂ in basaltic and ultramafic rocks is unique compared toconventional CCS, because it relies in part on rapidly proceedingchemical reactions which convert CO₂ gas to solids, rather than relyingon physical storage of CO₂ itself, either as a gas or liquid, over time.Economic estimates demonstrate the cost for one metric ton of CO₂captured by presently disclosed systems and methods is substantiallyless compared to conventional CCS.

In some embodiments, CO₂ gas is dissolved in water prior to or duringinjection into a basalt-containing reservoir, and this avoidsdifficulties including compressing and maintaining CO₂ in a liquidstate. Having CO₂ dissolved in an aqueous phase helps avoid the need fordrilling deep disposal wells deeper than about 850 m below the surface,as is required in conventional CCS. In other words, CSB requiressignificantly lower pressures to keep sufficient quantities of CO₂dissolved in water, and injection zones can be as shallow as 350vertical meters below surface for embodiments of the present disclosure.

Rapid immobilization of CO₂ as solid, stable carbonate minerals not onlyensures permanent removal of CO₂ from the environment, but alsoprecludes the need for sophisticated monitoring programs needed atconventional CCS sites. Extreme tolerance of the present technology tothe presence of up to about 40 mol. % of other water soluble waste gasessuch as H₂S, which like CO₂ is rapidly and substantially completelymineralized in basalts and ultramafics, also has important efficiencyimplications.

CSB negates the need for expensive and energy consuming steps to removesulfur/H₂S impurities from CO₂ and other gases produced during H₂production. Another important advantage is that in contrast to liquidCO₂, which is less dense than reservoir water and thus buoyant, CO₂-richwater has higher density than ambient groundwater. Consequently, wheninjected, CO₂-rich water will sink in the reservoir rather than moveupwards, which in some embodiments eliminates the need of a caprock—acritically important geological feature of all conventional CCSreservoirs. In embodiments of the present disclosure, injection andstorage of CO₂ in basalts and mafics has no impact on the quality ofgroundwater residing in those lithologies. This is particularlyimportant when such aquifers are used to supply drinking water or waterfor other purposes.

Therefore, disclosed here is a method for producing hydrogensubstantially without greenhouse gas emissions, the method includingproducing a product gas comprising hydrogen and carbon dioxide from ahydrocarbon fuel source; separating hydrogen from the product gas tocreate a hydrogen product stream and a byproduct stream; injecting thebyproduct stream into a reservoir containing mafic rock; and allowingcomponents of the byproduct stream to react in situ with components ofthe mafic rock to precipitate and store components of the byproductstream in the reservoir.

In some embodiments, the mafic rock comprises basaltic rock. In otherembodiments, before the step of injecting the byproduct stream into thereservoir, the byproduct stream is further treated to separate andpurify CO₂ from other components to increase CO₂ concentration of thebyproduct stream for injection into the reservoir. Still otherembodiments of the method further comprise the step of liquefying CO₂ inthe byproduct stream for injection into the reservoir. In someembodiments, the method includes the step of mixing the byproduct streamwith water, the byproduct stream comprising H₂S. In some embodiments,the method includes the step of reacting the separated hydrogen withnitrogen to form compressed liquid ammonia. Still other embodimentsinclude the steps of transporting the compressed liquid ammonia andreturning the compressed liquid ammonia to hydrogen and nitrogen viaelectrolysis for use of hydrogen as a hydrogen fuel source.

In still yet other embodiments, the step of producing a product gasincludes steam reforming or partial oxidation. In certain embodiments,the step of allowing components of the byproduct stream to react in situwith components of the mafic rock to precipitate produces precipitatesselected from the group consisting of: calcium carbonates, magnesiumcarbonates, iron carbonates, and combinations thereof. Still in otherembodiments, the reservoir is between about 250 m and about 700 m, or isbetween about 400 m and about 500 m, below the surface and is betweenabout 150° C. and about 280° C., or less. Temperatures in suitablereservoirs can be as low as about 30° C. In other embodiments, thereservoir is between about 700 m and about 2,200 m below the surface andis less than about 325° C.

Additionally disclosed here is a system for producing hydrogensubstantially without greenhouse gas emissions, the system including ahydrogen production unit with a hydrocarbon fuel inlet operable toproduce a product gas comprising hydrogen and carbon dioxide fromhydrocarbon fuel; a hydrogen separation unit operable to separatehydrogen from the product gas to create a hydrogen product stream and abyproduct stream; and an injection well operable to inject the byproductstream into a reservoir containing mafic rock to allow components of thebyproduct stream to react in situ with components of the mafic rock toprecipitate and store components of the byproduct stream in thereservoir. In some embodiments, the mafic rock comprises basaltic rock.In other embodiments, the system includes a byproduct treatment unit totreat the byproduct stream to separate and purify CO₂ from othercomponents and to increase CO₂ concentration of the byproduct stream forinjection into the reservoir.

Still in other embodiments, the system includes a compressor to liquefyCO₂ in the byproduct stream for injection into the reservoir. In certainembodiments, the system includes a mixing unit to mix the byproductstream with water, the byproduct stream comprising H₂S. Still in otherembodiments, the system includes a reaction unit to react the separatedhydrogen with nitrogen to form compressed liquid ammonia. In certainembodiments, the system includes a transportation unit to transport thecompressed liquid ammonia and return the compressed liquid ammonia tohydrogen and nitrogen via electrolysis for use of hydrogen as a hydrogenfuel source.

Still in other embodiments, the hydrogen production unit includes asteam reformer or partial oxidation reactor. In some embodiments,components of the produced byproduct stream react in situ withcomponents of the mafic rock to precipitate products selected from thegroup consisting of: calcium carbonates, magnesium carbonates, ironcarbonates, and combinations thereof. Still in other embodiments, thereservoir is between about 250 m and about 700 m, or is between about400 m and about 500 m, below the surface and is between about 150° C.and about 280° C., or less. Temperatures in suitable reservoirs can beas low as about 30° C. In other embodiments, the reservoir is betweenabout 700 m and about 2,200 m below the surface and is less than about325° C.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentdisclosure will become better understood with regard to the followingdescriptions, claims, and accompanying drawings. It is to be noted,however, that the drawings illustrate only several embodiments of thedisclosure and are therefore not to be considered limiting of thedisclosure's scope as it can admit to other equally effectiveembodiments.

FIG. 1 shows a schematic flow chart for an example embodiment of asystem for simultaneous H₂ production, H₂ transport, and CO₂sequestration for producing H₂ from hydrocarbons with near zerogreenhouse gas emissions.

DETAILED DESCRIPTION

So that the manner in which the features and advantages of theembodiments of systems and methods of H₂ production from hydrocarbonswith near zero greenhouse gas emissions, as well as others, which willbecome apparent, may be understood in more detail, a more particulardescription of the embodiments of the present disclosure brieflysummarized previously may be had by reference to the embodimentsthereof, which are illustrated in the appended drawings, which form apart of this specification. It is to be noted, however, that thedrawings illustrate only various embodiments of the disclosure and aretherefore not to be considered limiting of the present disclosure'sscope, as it may include other effective embodiments as well.

The production of H₂ from hydrocarbons using technologies such assteam-reforming or partial oxidation/gasification includes three steps.In steam reforming, hydrocarbons, for example methane, are heated in thepresence of H₂O (steam) and catalysts to release raw syngas consistingof hydrogen (H₂), carbon monoxide (CO), small amounts of carbon dioxide(CO₂), and/or other impurities as shown in Equations 1 and 2:

CH₄+H₂O↔CO+3H₂  Eq. 1

and/or

C_(n)H_(m) +nH₂O↔nCO+(n+0.5m)H₂  Eq. 2

The raw syngas is then treated to remove sulfur compounds and/orpurified further. H₂ yield is then maximized by reacting the raw syngaswith H₂O steam in the presence of catalyst to produce H₂ and CO₂according to Equation 3:

CO+H₂O→CO₂+H₂  Eq. 3

This is known as a water-gas shift reaction, hence the product is called“shifted” syngas. In partial oxidation, hydrocarbons are reacted withsmall (non-stoichiometric) amounts of oxygen (O₂) to produce raw syngasconsisting of H₂ and CO according to Equation 4:

CH₄+½O₂→CO+2H₂  Eq. 4

This raw syngas also contains minor amounts of CO₂ and/or nitrogen (N₂,if air was used instead of pure O₂). The raw syngas is then purified,and its H₂ content maximized by the reaction of Equation 3. Thecomposition of an example shifted syngas produced by both processes(steam reforming and partial oxidation) is presented in Table 1:

TABLE 1 Example shifted syngas composition from steam reforming orpartial oxidation. Component H₂ CO CO₂ N₂ O₂ Ar H₂S H₂O Other Mol. %40.9 1 29.8 2.4 0 0.4 0.01 25.4 0.11

Following water-gas shift, H₂ is purified by separation from CO₂ andother impurities by processes that employ adsorption, absorption, and/ormembrane filtration. One example process is pressure swing adsorption(“PSA”), which uses pressure-dependent selective adsorption propertiesof materials such as activated carbon, silica, and zeolites. Waste orbyproduct CO₂ and other impurities separated from H₂ during PSA are thenvented to the atmosphere. Unfortunately, if a conventional CCS schemewere to be used to sequester CO₂, then the CO₂ must be purified furtherand compressed to a liquid (supercritical) state for transportation andinjection in a deep reservoir. Both steps, however, are avoided (orsimplified significantly) here when CSB is applied instead.

While conventional CCS relies predominantly on physical processes suchas the injection and storage of single phase liquid CO₂ in non-reactiverock reservoirs (e.g., sandstone, limestone), CSB relies on thenaturally occurring chemical reactions between CO₂ and mafic andultramafic rocks to precipitate solid carbonates. Reactions include thefollowing: first CO₂ dissolves in and reacts with water (either or bothwater supplied with CO₂ gas at the surface or water present in situ in amafic reservoir) to form a week carbonic acid as shown in Equations 5-7:

CO₂+H₂O↔H₂CO_(3(aq))  Eq. 5

H₂CO₃↔HCO₃ ⁻+H⁺  Eq. 6

HCO₃ ⁻↔CO₃ ²⁻+H⁺  Eq. 7

Acidified water dissolves Ca, Fe, and Mg-rich silicate phases (mineralsand/or volcanic glass) which results in the release of divalent metalions in solution according to Equation 8:

(Mg,Fe,Ca)₂SiO₄+4H⁺→2(Mg,Fe,Ca)²⁺+2H₂O+SiO_(2(aq))  Eq. 8

CO₃ ²⁻ formed during the reaction shown in Equation 7 reacts with thedivalent metal cations leading to the precipitation of carbonateminerals as shown in Equation 9:

(Ca,Mg,Fe)²⁺+CO₃ ²⁻→(Ca,Mg,Fe)CO₃  Eq. 9

Geochemical reaction-transport modeling demonstrates that mineral phases(for example calcite, siderite, and magnesite) will remain stable underprevailing subsurface conditions, hence safely removing CO₂ from theatmosphere for hundreds of thousands to millions of years. Othercarbonate minerals include ankerite Ca[Fe, Mg, Mn](CO3)₂. In addition,CSB has extreme tolerance for other water soluble acid gas impurities(e.g. H₂S, which is also mineralized as sulphides). Such an advantageousquality not only simplifies the process further, eliminating the need toremove those impurities from a gas mixture exiting an H₂ productionprocess, but it also allows for simultaneous sequestering of all otherH₂O soluble gas contaminants capable of forming stable mineral phases byreacting with basalts/ultramafics.

CO₂ dissolution in water for CSB can be achieved by either: a)separately injecting CO₂ and water in the tubing and annular space ofinjector wells and allowing these to mix at or below about a 350 m depthin the wellbore prior to entering the reservoir; orb) dissolving CO₂ andwater at the surface in a pressurized vessel and then injecting thesolution in a basalt/ultramafic reservoir. While the first methodgenerally applies to pure CO₂ and/or a mixture of CO₂ and other watersoluble acid gases, the latter method is used to effectively separateCO₂ (and other water soluble gases) from insoluble or weekly solubleimpurities, and can therefore be used to process complex flue gasmixtures (e.g. shifted syngas).

Due to certain thermodynamic constraints of CO₂ dissolution in water,both methods require about 27 tons of H₂O per 1 ton of CO₂ sequestered.In areas where water is in short supply, CSB may be done by injectingsupercritical (liquid) CO₂ in basalts or ultramafics; however, thiswould increase energy demands due to the need for liquefying CO₂ viacompression.

With respect to the produced H₂, conventionally H₂ is stored andtransported as a liquid at a temperature of about −253° C., whichrequires special double-walled isolated vessels in addition to oralternative to constant refrigeration. However, reversible chemicalconversion of H₂ into liquid ammonia (NH₃) allows storage andtransportation of H₂ at low pressure and ambient temperatures, atgreatly reduced volumes. The reversible H₂ to NH₃ storage and transportmethod is inherently safer and advantageous in particular where largevolumes of H₂ are to be stored and transported.

Due to high tolerance of CSB to impurities in the CO₂ stream (such asH₂S and other gases), CO₂-rich tail gases from other sources such asrefining, power production, and desalinization could, after limitedtreatment, be either added to the principal waste stream orindependently injected into reactive lithologies for permanentimmobilization and disposal.

Unexpected and surprising advantages of simultaneously producing H₂ fromhydrocarbons while using CSB for permanent CO₂ immobilization in basaltsand ultramafics include significantly lower predicted energy usage andcost due to: lower energy consumption and lower well costs because thereis no requirement to compress and liquefy the CO₂; lower complexity ofoperations due to high tolerance to impurities in the CO₂ stream;simultaneous removal of H₂S along with CO₂ in the reservoirs viaprecipitation as solids; no need for a reservoir caprock; and no needfor sophisticated long-term monitoring programs. There is no need toliquefy CO₂ when it is dissolved in water either at the surface or inthe wellbore, but it would be liquefied if directly injected in thesubsurface as supercritical fluid.

FIG. 1 shows a schematic flow chart for an example embodiment of asystem for simultaneous H₂ production, H₂ transport, and CO₂sequestration for producing H₂ from hydrocarbons with near zerogreenhouse gas emissions. In system 100, a hydrocarbon inlet 102provides a hydrocarbon source, for example natural gas, to a hydrogenproduction system 104. Hydrogen production system 104 might includesteam reforming or partial oxidation, and water-gas shift reactions, forexample as described in Equations 1-4. Production gases exit via outlet106 to a separation unit 108. Separation unit 108 is operable toseparate hydrogen from CO₂ and other byproducts, and can include forexample one or more absorption units, adsorption units, membraneseparation units, or any suitable separation technology for separatingH₂ from CO₂ and other product gases, such as for example acid gases.

CO₂ and additional gases such as acid gases exit separation unit 108 viaoutlet 110 and can optionally proceed to a further CO₂ purification andliquidification unit 112, but need not to. In the case of further CO₂purification and liquidification unit 112, liquefied CO₂ is injectedinto basaltic formation 116 via injection well 114 to form solidprecipitated metal carbonates per Equations 5-9. Without optionalfurther CO₂ purification and liquidification unit 112, CO₂ andadditional gases such as acid gases exit separation unit 108 via outlet110 and proceed directly into basaltic formation 116 via injection well114 to form solid precipitated metal carbonates per Equations 5-9. CO₂can be mixed with water as a gas at the surface or in situ in basalticformation 116, or both. Solid carbonate nodules form in vugs and veinsin basalt around injection wells and extending outwardly from theinjection wells.

Rates of basalt dissolution and mineral carbonation reactions canincrease with increasing temperature, and thus higher temperaturebasaltic reservoirs may be advantageous, while deep reservoirs beyondabout 350 m are not required because high pressures are not required tokeep CO₂ in a pressurized or liquid state. Reservoir temperature can beas low as about 30° C. and as high as about 280° C., but generally nothigher than about 325° C., above which temperature certain carbonateminerals become thermodynamically unstable. An example suitablereservoir temperature is about 185° C., or for example between about150° C. and about 280° C. As explained, injected CO₂, either by itselfor with other gases, optionally dissolved in water, creates an acidicenvironment near the injection well, such as injection well 114. Nearinjection well 114, the acidic fluids remain undersaturated with respectto basaltic minerals and volcanic glass.

Undersaturation and acidity leads to dissolution of host rock basalts inthe vicinity of injection wells, such as injection well 114.Mineralization then mostly occurs at a distance away from the injectionwell (which allows continuous injection of CO₂ in a reservoir such asbasaltic formation 116), after sufficient dissolution of host basalticrock neutralizes the acidic water and saturates the formation water withrespect to carbonate and sulfur minerals.

Hydrogen exits separation unit 108 at outlet stream 118 to proceed toreaction unit 120 where hydrogen is reacted with nitrogen to formammonia (NH₃). Ammonia exits reaction unit 120 at outlet 122 for reducedvolume transport of H₂ as NH₃. Reaction unit 120 can include apressurized multistage ammonia production system (PMAPS) to produceammonia in a pressurized liquid phase. Pressurized liquid NH₃ can betransported by a pressurized tanker truck, and using an NH₃electrolyzer, NH₃ can be reversibly returned to N₂ and H₂ whereverhydrogen is required.

The singular forms “a,” “an,” and “the” include plural referents, unlessthe context clearly dictates otherwise.

The term “about” when used with respect to a value or range refers tovalues including plus and minus 5% of the given value or range.

In the drawings and specification, there have been disclosed embodimentsof systems and methods for H₂ production from hydrocarbons with nearzero greenhouse gas emissions of the present disclosure, and althoughspecific terms are employed, the terms are used in a descriptive senseonly and not for purposes of limitation. The embodiments of the presentdisclosure have been described in considerable detail with specificreference to these illustrated embodiments. It will be apparent,however, that various modifications and changes can be made within thespirit and scope of the disclosure as described in the foregoingspecification, and such modifications and changes are to be consideredequivalents and part of this disclosure.

That claimed is:
 1. A system for producing hydrogen substantiallywithout greenhouse gas emissions, the system comprising: a hydrogenproduction unit with a hydrocarbon fuel inlet operable to produce aproduct gas comprising hydrogen and carbon dioxide from hydrocarbonfuel; a hydrogen separation unit operable to separate hydrogen from theproduct gas to create a hydrogen product stream and a byproduct streamcomprising CO₂; and an injection well operable to inject the byproductstream into a reservoir containing mafic rock to allow components of thebyproduct stream to react in situ with components of the mafic rock toprecipitate and store components of the byproduct stream in thereservoir.
 2. The system according to claim 1, where the mafic rockcomprises basaltic rock.
 3. The system according to claim 1, furthercomprising a byproduct treatment unit to treat the byproduct stream toseparate and purify CO₂ from other components and to increase CO₂concentration of the byproduct stream for injection into the reservoir.4. The system according to claim 1, further comprising a compressor toliquefy CO₂ in the byproduct stream for injection into the reservoir. 5.The system according to claim 1, further comprising a mixing unit to mixthe byproduct stream with water, the byproduct stream comprising H₂S. 6.The system according to claim 1, further comprising a reaction unit toreact the separated hydrogen with nitrogen to form compressed liquidammonia.
 7. The system according to claim 6, further comprising atransportation unit to transport the compressed liquid ammonia andreturn the compressed liquid ammonia to hydrogen and nitrogen viaelectrolysis for use of hydrogen as a hydrogen fuel source.
 8. Thesystem according to claim 1, where the hydrogen production unit includesa steam reformer or partial oxidation reactor.
 9. The system accordingto claim 1, where components of the produced byproduct stream react insitu with components of the mafic rock to precipitate products selectedfrom the group consisting of: calcium carbonates, magnesium carbonates,iron carbonates, and combinations thereof.
 10. The system according toclaim 1, where the reservoir is between about 250 m and about 2,200 mbelow the surface and is between about 30° C. and about 325° C.
 11. Thesystem according to claim 1, where the reservoir is between about 350 mand about 1,500 m below the surface and is less than about 325° C.